Use of natural gas for deliquification

ABSTRACT

A method for producing hydrocarbons from a well that includes a borehole, production tubing in the borehole, and an annulus between the production tubing and the borehole, the borehole containing an undesirable amount of liquid, comprises the steps of: a) providing a source of liquefied natural gas (LNG), b) regasifying the LNG, c) pressurizing the regasified LNG to a pressure above the pressure in the annulus, d) injecting the pressurized regasified LNG into the annulus, e) allowing the pressurized regasified LNG to flow into and up through the production tubing; thereby reducing the amount of liquid in the borehole, f) recovering the pressurized regasified LNG along with produced gas and transmitting both.

TECHNICAL FIELD/FIELD OF THE DISCLOSURE

The present invention relates generally to systems and methods for fluids from a wellbore and more particularly to such systems and methods deliquefying or dewatering natural gas wells.

BACKGROUND OF THE DISCLOSURE

Oil and gas are produced from wells that penetrate subsurface hydrocarbon-bearing reservoirs. Such reservoirs are pressurized by the weight of the formations above the reservoir. When a well penetrates a formation, hydrocarbons and other fluids in the formation will tend to flow into the well because of the formation pressure. Formation fluids flow into the well as long as the pressure in the wellbore is less than the formation pressure. The flow of fluids out of the formation reduces formation pressure, however, and eventually production ceases because the borehole pressure equals or exceeds the formation pressure.

In addition to its own produced water, a well can retain water from the fracking process or receive water from a neighboring well that is being fracked with water (communicated water). Regardless of its source, the water accumulating in the bottom of the borehole can exert sufficient hydrostatic pressure to stop or sharply reduce production. In such cases, the well must be unloaded with a swab rig or by other methods. These processes require extensive permitting and emissions monitoring in many locations.

Various types of lift or pumping devices have been used to extract fluids from wells, including gas-lift systems, in which high-pressure gas is injected into a well below a volume of liquid. The injected gas expands and rises, in the process lifting the liquid to the surface. Typically, a gas lift production system utilizes injection of compressed gas into production tubing to aerate the produced fluids, causing them to flow more readily to the surface. The gas is typically separated from the oil at the surface and flared. Gas lift methods can be continuous or intermittent.

Another technique for removing downhole liquids is plunger lift. A plunger fits within the production tubing and acts as a piston. It depends on downhole pressure to rise and on gravity to return to the bottom of the well. FIG. 1 illustrates a typical plunger lift installation. Plunger lift is cyclic, with the well alternately flowing and shut-in. When the well is flowing, the plunger is at the bottom of the hole and liquids accumulate in the bottom of the tubing. During a shut-in period, gas pressure accumulates in the annulus. The pressure in the annulus depends on the shut-in time, reservoir pressure, formation permeability. When the annulus pressure has reached a desired level, a valve is opened at the surface to allow the well to flow. The pressurized annulus gas expands into the tubing, lifting the plunger and liquids to the surface. The plunger is then allowed to fall back into the hole and the cycle repeats.

Still another technique includes a combination of gas lift and plunger lift technologies. In some such systems, the annulus is continuously charged with compressed gas to build energy which is periodically released to lift accumulated fluids, using a combination of plunger and gas lift techniques. The wellbore annulus can be fitted with a packer to create an annular chamber that is continuously charged with gas to create a large pressure differential compared to that present in the reservoir alone. A valve in the tubing string alternates between a production position in which production fluids bypass the valve and flow to the surface and a lift position in which the bypass is blocked and an unloading port opens to vent high pressure annulus gas to the tubing string above the valve, lifting accumulated liquids with it. The valve is actuated to the lift position when the pressure in the annulus has reached a predetermined threshold. When the gas has been vented and the pressure in the annulus drops, the valve is returned to the production position.

Typically, a reservoir is allowed to produce gas until liquids begin to accumulate in the wellbore and the production rate decreases to some value near a predetermined critical rate. The well is then closed, and the plunger falls back to the bumper spring, first through gas and then through some accumulated liquid.

SUMMARY

According to some embodiments, a method for producing hydrocarbons from a well that includes a borehole, production tubing in the borehole, and an annulus between the production tubing and the borehole, the borehole containing an undesirable amount of liquid, may comprise the steps of a) providing a source of liquefied natural gas (LNG), b) regasifying the LNG, c) pressurizing the regasified LNG to a pressure above the pressure in the annulus, d) injecting the pressurized regasified LNG into the annulus, e) allowing the pressurized regasified LNG to flow into and up through the production tubing; thereby reducing the amount of liquid in the borehole, and f) recovering the pressurized regasified LNG along with produced gas and transmitting both.

The LNG may comprise at least 95% methane or at least 98% methane. Step b) may comprise passing the LNG through a vaporizer to produce a regasified LNG stream and step c) may comprises passing the regasified LNG stream through a compressor to produce a pressurized regasified LNG stream. Step f) may be carried out without further separation of the recovered gases. The method may further include the step of sensing when an undesired amount of liquid has accumulated in the borehole and may, if desired include using a plunger to facilitate movement of liquid out of the borehole.

The vaporization step may include using heat from ambient air, electric heat, or heat from combusting a fuel.

In some embodiments, an apparatus for producing hydrocarbons from a well that includes a borehole, production tubing in the borehole, and an annulus between the production tubing and the borehole, the borehole containing an undesirable amount of liquid, the apparatus may comprise a tank of liquefied natural gas (LNG), a vaporizer for regasifying the LNG, a compressor for pressurizing the regasified LNG to a pressure above the pressure in the annulus; and a fluid connection for injecting the pressurized regasified LNG into the annulus.

The LNG may comprise at least 95% methane or at least 98% methane. The apparatus may further include a sensor adapted to sense when an undesired amount of liquid has accumulated in the borehole. The apparatus may further include a plunger in the tubing for facilitating movement of liquid out of the borehole. The vaporizer may use heat from ambient air, electric heat, or heat from combusting a fuel.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic diagram of a plunger lift system.

FIG. 2 is a schematic diagram illustrating an embodiment of the invention.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.

Referring briefly to FIG. 2, wellbore 10 extends from the surface 12 into or through a gas-producing reservoir 14. Wellbore 10 may be lined with a casing 16. All or a portion of the annulus between wellbore 10 and casing 16 may be filled with cement 17 or other sealants such that migration of fluids through the annulus is prevented. A tubing string 20 extends through casing 16 from surface 12 and has an open lower end 22. A plurality of perforations 18 may be formed through casing 16 in the vicinity of reservoir 15 so as to permit reservoir fluids to flow into casing. Thus, two fluid passages are provided between reservoir 15 and surface 12, namely the annulus 24 between casing 16 and tubing string 20 and the inner bore of tubing string 20.

As illustrated, water and other liquids 30 may be produced and may collect at the bottom of the well. As mentioned, the water level in the wellbore may attain a height such that its hydrostatic pressure impairs the production of gas from reservoir 15. In those circumstances, the present method can be used to remove that accumulated water and other liquids.

According to some embodiments of the invention, liquefied natural gas (LNG) or compressed natural gas (CNG) is used to clear the well.

As-produced, raw natural gas typically includes various hydrocarbons. For example, natural gas may include methane, ethane, propane, butanes, pentanes, other hydrocarbons, as well as water and other impurities such as nitrogen, carbon dioxide, hydrogen sulfide and helium, with methane typically a major component. By way of example, the concentration of methane in raw natural gas may be about 90%.

LNG is typically produced by feeding natural gas into a liquefaction module. In order to store and transport natural gas as liquid, the natural gas is cooled to −240° to −260° F. (−151° C. to −162° C.), at which temperature the vapor pressure is close to 1 atm (101 kPa). Liquefaction systems entail sequentially passing the gas at an elevated pressure through a plurality of cooling stages in which the gas is cooled to successively lower temperatures until the liquefaction temperature is reached. Cooling is generally accomplished by indirect heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, methane, nitrogen, carbon dioxide, or combinations of the preceding refrigerants.

The liquefaction process removes all non-hydrocarbon contaminates (CO₂, dirt, oil, water) from the natural gas, providing an ultraclean form of gas. In some instances, C₂₊ hydrocarbons that condense during the liquefaction process are allowed to remain in the LNG product. In other instances, and typically in commercial LNG processes in the United States, C₂₊ hydrocarbons are removed during the liquefaction process, so that the resulting LNG typically comprises at least 95% methane and more typically comprises at least about 98% methane. Either form of LNG may be used in the present process and the term LNG is used herein to refer to either.

According to some embodiments, the LNG is provided in a reusable storage tank. From the tank, the LNG is fed to a vaporizer and then to a compressor. Alternatively, the LNG may be sent to a high-pressure pump and then to a vaporizer. In either case, the output comprises regasified gas at a pressure slightly above the well casing pressure, which may be 150 to 4500 psig (1,034 to 31,026 kPa).

Heat for regasifying (vaporizing) the LNG may be provided from any suitable source, including but not limited, ambient air, electric heating, combustion of gas or other fuel, or any other heat source.

The pressurized, regasified gas is injected into the well casing as illustrated at arrow 32 and increases the well casing pressure. The pressurized gas thus forces the downhole liquids up through the tubing as illustrated at arrow 34, thereby clearing the well bore, reducing hydrostatic head at the bottom of the hole, and restoring gas flow.

In some embodiments, a plunger may be used in combination with the injected LNG or CNG. In these embodiments, conventional equipment for receiving the plunger at the surface is also used and the well is cycled to allow the plunger to intermittently carry fluids from the bottom of the hole to the surface and to allow fluids to accumulate above the plunger during the intervals therebetween.

Once it has returned to the surface, the pressurized, regasified natural gas injected into the well can be separated from the produced liquids and sent to a gas production line for transmission to a gas processing facility, instead of to a flare or vent stack. Because LNG is cleaner than produced gas, in some instances, the lift gas returning to the surface may be fed directly into production lines following separation from the produced liquids. Likewise, since LNG is better than pipeline gas quality, the injected gas returning to the surface requires no further processing for sales. This allows the well to put products from the well into the sales line almost immediately; upon completion of this process, the well will be back in production of oil and natural gas with minimal impact on the environment

Because of its compressed nature, a large amount of gas for use in the present method can be delivered to a well in the form LNG. Thus, the present process can operate for an extended period of time, unmanned, without violating emission regulations or permits. Similarly, the equipment required to operate the present process is more compact and can operate on well sites whose size or location restrict access by traditional methods.

The present well bore unloading process can unload liquids from a well more quickly with less expense and without the emissions of the traditional swab rig process. Likewise, because the regasified LNG does not require cleaning before sale, the well can return to production more quickly than if well gas were used for deliquification.

Well gas including CO₂, NGLs, and methane are all greenhouse gases. Because storage and/or cleanup may be impractical in some instances, gas that does not meet the pipeline specification may need to be flared. The traditional process causes these to be emitted to atmosphere, which can violate air permits. The present process reduces these emissions to nearly zero.

The foregoing outlines features of several embodiments so that a person of ordinary skill in the art may better understand the aspects of the present disclosure. Such features may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed herein. One of ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. One of ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure. 

What is claimed is:
 1. A method for producing hydrocarbons from a well that includes a borehole, production tubing in the borehole, and an annulus between the production tubing and the borehole, the borehole containing an undesirable amount of liquid, the method comprising the steps of: a) providing a source of liquefied natural gas (LNG); b) regasifying the LNG; c) pressurizing the regasified LNG to a pressure above the pressure in the annulus; d) injecting the pressurized regasified LNG into the annulus; e) allowing the pressurized regasified LNG to flow into and up through the production tubing; thereby reducing the amount of liquid in the borehole; and f) recovering the pressurized regasified LNG along with produced gas and transmitting both.
 2. The method of claim 1 wherein the LNG comprises at least 95% methane.
 3. The method of claim 1 wherein the LNG comprises at least 98% methane.
 4. The method of claim 1 wherein step b) comprises passing the LNG through a vaporizer to produce a regasified LNG stream.
 5. The method of claim 1 wherein step c) comprises passing the regasified LNG stream through a compressor to produce a pressurized regasified LNG stream.
 6. The method of claim 1 wherein step f) is carried out without further separation of the recovered gases.
 7. The method of claim 1, further including the step of sensing when an undesired amount of liquid has accumulated in the borehole.
 8. The method of claim 1 wherein step e) includes using a plunger to facilitate movement of liquid out of the borehole.
 9. The method of claim 1 wherein step b) includes using heat from ambient air.
 10. The method of claim 1 wherein step b) includes using electric heat or heat from combusting a fuel.
 11. An apparatus for producing hydrocarbons from a well that includes a borehole, production tubing in the borehole, and an annulus between the production tubing and the borehole, the borehole containing an undesirable amount of liquid, the apparatus comprising: a tank of liquefied natural gas (LNG); a vaporizer for regasifying the LNG; a compressor for pressurizing the regasified LNG to a pressure above the pressure in the annulus; and a fluid connection for injecting the pressurized regasified LNG into the annulus.
 12. The apparatus of claim 1 wherein the LNG comprises at least 95% methane.
 13. The apparatus of claim 1 wherein the LNG comprises at least 98% methane.
 14. The apparatus of claim 1, further including a sensor adapted to sense when an undesired amount of liquid has accumulated in the borehole.
 15. The apparatus of claim 1, further including a plunger in the tubing for facilitating movement of liquid out of the borehole.
 16. The apparatus of claim 1 wherein the vaporizer uses heat from ambient air.
 17. The apparatus of claim 1 wherein the vaporizer uses electric heat or heat from combusting a fuel. 